1. Field of the Invention
The present invention relates to the field of moderation of environments where animal are stored or housed and release waste into an area adjacent, under or into the environment. The invention relates to moderating effects of microbes and gaseous emissions from the waste and to the ability to use bound waste safely and effectively in agricultural applications.
2. Background of the Art
The exploitation of bituminous sands dates back to paleolithic times. The earliest known use of bitumen was by Neanderthals, some 40,000 years ago. Bitumen has been found adhering to stone tools used by Neanderthals at sites in Syria. After the arrival of Homo sapiens, humans used bitumen for construction of buildings and water proofing of reed boats, among other uses.
In ancient times, bitumen was primarily a Mesopotamian commodity used by the Sumerians and Babylonians, although it was also found in the Levant and Persia. Along the Tigris and Euphrates rivers, the area was littered with hundreds of pure bitumen seepages. The Mesopotamians used the bitumen for waterproofing boats and buildings. In North America, the early European fur traders found Canadian First Nations using bitumen from the vast Athabasca oil sands to waterproof their birch bark canoes. In Europe, they were extensively mined near the European city of Pechelbronn, where the vapor separation process was in use in 1742.
The name “tar sands” was applied to bituminous sands in the late 19th and early 20th century. People who saw the bituminous sands during this period were familiar with the large amounts of tar residue produced in urban areas as a by-product of the manufacture of coal gas for urban heating and lighting. Naturally occurring bitumen is chemically more similar to asphalt than to tar, and the term “oil sands” (or oilsands) is more commonly used in the producing areas than tar sands because synthetic oil is what is manufactured from the bitumen.
Tar sands are now considered a serious alternative to conventional crude oil, since crude oil is becoming scarce. Oil sands and oil shale have the potential to generate oil for centuries. Oil sands may represent as much as two-thirds of the world's total petroleum resource, with at least 1.7 trillion barrels (270×109 m3) in the Canadian Athabasca Oil Sands. In October 2009, the USGS updated the Orinoco tar sands (Venezuela) mean estimated recoverable value to 513 billion barrels (8.16×1010 m3), making it one of the world's largest recoverable oil deposits.
Bituminous sands are a major source of unconventional oil. Conventional crude oil is normally extracted from the ground by drilling oil wells into a petroleum reservoir, allowing oil to flow into them under natural reservoir pressures, although artificial lift and techniques such as water flooding and gas injection are usually required to maintain production as reservoir pressure drops toward the end of a field's life. Because extra-heavy oil and bitumen flow very slowly, if at all, toward producing wells under normal reservoir conditions, the sands must be extracted by strip mining or the oil made to flow into wells by in situ techniques which reduce the viscosity by injecting steam, solvents, and/or hot air into the sands. These processes can use more water and require larger amounts of energy than conventional oil extraction, although many conventional oil fields also require large amounts of water and energy to achieve good rates of production. This is because heavy crude feedstock needs pre-processing before it is fit for conventional refineries. This pre-processing is called ‘upgrading’, the key components of which are as follows:                1. removal of water, sand, physical waste and lighter products        2. catalytic purification by hydrodemetallisation (HDM), hydrodesulfurization (HDS) and hydrodenitrogenation (HDN)        3. hydrogenation through carbon rejection or catalytic hydrocracking (HCR)As carbon rejection is very inefficient and wasteful in most cases, catalytic hydrocracking is preferred in most cases. All these processes take large amounts of energy and water, while emitting more carbon dioxide than conventional oil.        
Catalytic purification and hydrocracking are together known as hydroprocessing. The big challenge in hydroprocessing is to deal with the impurities found in heavy crude, as they poison the catalysts over time. Many efforts have been made to deal with this to ensure high activity and long life of a catalyst. Catalyst materials and pore size distributions are key parameters that need to be optimized to deal with these challenges and this varies from place to place depending on the kind of feedstock present.
The heavy crude oil or crude bitumen extracted from oil sands is a viscous, solid or semisolid form that does not easily flow at normal oil pipeline temperatures, making it difficult to transport to market and expensive to process into gasoline, diesel fuel, and other products. Despite the difficulty and cost, oil sands are now being mined by energy companies on a vast scale to extract the bitumen, which is then converted into synthetic oil (syncrude) by bitumen upgraders, or refined directly into petroleum products by specialized refineries.
Surface Mining
Since Great Canadian Oil Sands (now Suncor) started operation of its mine in 1967, bitumen has been extracted on a commercial scale from the Athabasca Oil Sands by surface mining. In the Athabasca sands there are very large amounts of bitumen covered by little overburden, making surface mining the most efficient method of extracting it. The overburden consists of water-laden muskeg (peat bog) over top of clay and barren sand. The oil sands themselves are typically 40 to 60 m deep, sitting on top of flat limestone rock. Originally, the sands were mined with draglines and bucket-wheel excavators and moved to the processing plants by conveyor belts. In recent years companies have switched to much cheaper shovel-and-truck operations using the biggest power shovels (100 or more tons) and dump trucks (400 tons) in the world. This has held production costs to around $27 per barrel of synthetic crude oil despite rising energy and labor costs.
After excavation, hot water and caustic soda (NaOH) are added to the sand, and the resulting slurry is piped to the extraction plant where it is agitated and the oil skimmed from the top. Provided that the water chemistry is appropriate to allow bitumen to separate from sand and clay, the combination of hot water and agitation releases bitumen from the oil sand, and allows small air bubbles to attach to the bitumen droplets. The bitumen froth floats to the top of separation vessels, and is further treated to remove residual water and fine solids. Bitumen is much thicker than traditional crude oil, so it must be either mixed with lighter petroleum (either liquid or gas) or chemically split before it can be transported by pipeline for upgrading into synthetic crude oil. The bitumen is then transported and eventually upgraded into synthetic crude oil. About two tons of oil sands are required to produce one barrel (roughly ⅛ of a ton) of oil. Originally, roughly 75% of the bitumen was recovered from the sand. However, recent enhancements to this method include Tailings Oil Recovery (TOR) units which recover oil from the tailings, Diluent Recovery Units to recover naptha from the froth, Inclined Plate Settlers (IPS) and disc centrifuges. These allow the extraction plants to recover well over 90% of the bitumen in the sand. After oil extraction, the spent sand and other materials are then returned to the mine, which is eventually reclaimed.
Alternative process technology extracts bitumen from oil sands through a dry-retorting. During this process, oil sand is moved through a rotating drum, cracking the bitumen with heat and producing lighter hydrocarbons. Although tested, this technology is not in commercial use yet.
It is estimated that approximately 90% of the Alberta oil sands and nearly all of Venezuelan sands are too far below the surface to use open-pit mining. Several in-situ techniques have been developed to extract this oil.
Cold heavy oil production with sand—In this technique, also known as cold heavy oil production with sand (CHOPS), the oil is simply pumped out of the sands, often using progressive cavity pumps. This only works well in areas where the oil is fluid enough. It has the advantage of being cheap and the disadvantage that it recovers only 5-6% of the oil in place. By removing the sand filters from the wells and the process produced as much sand as possible with the oil, production rates improved remarkably. Further research disclosed that pumping out sand opened “wormholes” in the sand formation which allowed more oil to reach the wellbore. The advantage of this method is better production rates and recovery (around 10%) and the disadvantage that disposing of the produced sand is a problem. A novel way to do this was spreading it on rural roads, which rural governments liked because the oily sand reduced dust and the oil companies did their road maintenance for them. However, governments have become concerned about the large volume and composition of oil spread on roads, so in recent years disposing of oily sand in underground salt caverns has become more common.
Cyclic Steam Stimulation (CSS) or Steam injection (oil industry)—The use of steam injection to recover heavy oil has been in use in the oil fields of California since the 1950s. The Cyclic Steam Stimulation or “huff-and-puff” method has been in use by Imperial Oil at Cold Lake since 1985. In this method, the well is put through cycles of steam injection, soak, and oil production. First, steam is injected into a well at a temperature of 300 to 340 degrees Celsius for a period of weeks to months; then, the well is allowed to sit for days to weeks to allow heat to soak into the formation; and, later, the hot oil is pumped out of the well for a period of weeks or months. Once the production rate falls off, the well is put through another cycle of injection, soak and production. This process is repeated until the cost of injecting steam becomes higher than the money made from producing oil. The CSS method has the advantage that recovery factors are around 20 to 25% and a disadvantage that the cost to inject steam is high.
Steam assisted gravity drainage—Steam assisted gravity drainage was developed in the 1980s and fortuitously coincided with improvements in directional drilling technology that made it quick and inexpensive to do by the mid 1990s. In SAGD, two horizontal wells are drilled in the oil sands, one at the bottom of the formation and another about 5 m above it. These wells are typically drilled in groups off central pads and can extend for miles in all directions. In each well pair, steam is injected into the upper well and the heat melts the bitumen, which allows it to flow into the lower well, where it is pumped to the surface. SAGD is cheaper than CSS, allows very high oil production rates, and recovers up to 60% of the oil in place. Because of its very favorable economics and applicability to a vast area of oil sands, this method alone quadrupled North American oil reserves and allowed Canada to move to second place in world oil reserves after Saudi Arabia.
Vapor Extraction Process (VAPEX)—This process is similar to SAGD but instead of steam, hydrocarbon solvents are injected into the upper well to dilute the bitumen and allow it to flow into the lower well. It has the advantage of much better energy efficiency than steam injection and it does some partial upgrading of bitumen to oil right in the formation.
The above three methods are not mutually exclusive. It is becoming common for wells to be put through one CSS injection-soak-production cycle to condition the formation prior to going to SAGD production, and companies are experimenting with combining VAPEX with SAGD to improve recovery rates and lower energy costs.
Toe to Heel Air Injection (THAI)—This is a very new and experimental method that combines a vertical air injection well with a horizontal production well. The process ignites oil in the reservoir and creates a vertical wall of fire moving from the “toe” of the horizontal well toward the “heel”, which burns the heavier oil components and upgrades some of the heavy bitumen into lighter oil right in the formation. Historically fireflood projects have not worked out well because of difficulty in controlling the flame front and a propensity to set the producing wells on fire. However, some oil companies feel the THAI method will be more controllable and practical, and have the advantage of not requiring energy to create steam. Advocates of this method of extraction state that it uses less freshwater, produces 50% less greenhouse gas and has a smaller footprint than other production techniques.
Combustion Overhead Gravity Drainage (COGD)—This is an experimental method that employs an number of vertical air injection wells above a horizontal production well located at the base of the bitumen pay zone. An initial Steam Cycle similar to CSS is used to prepare the bitumen for ignition and mobility. Following that cycle, air is injected into the vertical wells, igniting the upper bitumen and mobilizing (through heating) the lower bitumen to flow into the production well. It is expected that COGD will result in water savings of 80% compared to SAGD.
Like all mining and non-renewable resource development projects, oil sands operations have an adverse effect on the environment. Oil sands projects affect: the land when the bitumen is initially mined and with large deposits of toxic chemicals; the water during the separation process and through the drainage of rivers; and the air due to the release of carbon dioxide and other emissions, as well as deforestation. Additional indirect environmental effects are that the petroleum products produced are mostly burned, releasing carbon dioxide into the atmosphere.
One of the greatest environment concerns in oil sand is with water contamination and in the actual production of contaminated water rather than merely adding contaminants that could be controlled to existing water supplies. Between 2 to 4.5 volume units of water are used to produce each volume unit of synthetic crude oil (SCO) in an ex-situ mining operation. Despite recycling, almost all of it ends up in tailings ponds, which, as of 2007, covered an area of approximately 50 km2 (19 sq mi). In SAGD operations, 90 to 95 percent of the water is recycled and only about 0.2 volume units of water is used per volume unit of bitumen produced. Large amounts of water are used for oil sands operations—Greenpeace gives the number as 349 million cubic meters per year, twice the amount of water used by the city of Calgary. It is unclear if this is the amount of water they are licensed to remove from the Athabasca or the actual use and how up to date the statistic is. The Athabasca River is also much larger than Bow and Elbow rivers that flow through Calgary.
In October 2009, Suncor Energy announced it was seeking government approval for a new process to recover tailings called Tailings Reduction Operations (TRO), which accelerates the settling of fine clay, sand, water, and residual bitumen in ponds after oil sands extraction. The technology involves dredging mature tailings from a pond bottom, mixing the suspension with a polymer flocculent, and spreading the sludge-like mixture over a “beach” with a shallow grade. According to the company, the process could reduce the time for water reclamation from tailings to weeks rather than years, with the recovered water being recycled into the oil sands plant. In addition to reducing the number of tailing ponds, Suncor claims TRO could reduce the time to reclaim a tailing pond from 40 years at present to 7-10 years, with land rehabilitation continuously following 7 to 10 years behind the mining operations.
Even with the improvements in extraction and storage techniques, the water issues involved with oil sand and residual water from the related processing are further complicated by the fact that these water residues become sources for bacterial contamination and build-up. The open water storage and the mineral and organic content in the residual waters promote bacteria growth and become more hazardous over time. Because of the increasing economic importance of oil sand extraction of hydrocarbons, any technology to further ameliorate residual water issues and particularly the bacterial build-up in the residual waters is important.
The following Published U.S. patent application Documents disclose related technology for treatment of various situations and conditions that have been developed by the present inventor and are incorporated herein by reference in their entirety, Published U.S. Patent Documents 20090028915; 20090193562; 20090145391; 2008121592; 20080095812; 20080063694; and 20080063560. Some of these references disclose the combination of cupric sulfate and potassium iodide combined with superabsorbent polymers, and includes disclosure of adding those materials directly onto flooring and bedding in stalls for animals. This bedding, usually in single animal stalls, must be turned and removed as is bedding, but delays the time period between bedding replacement.
U.S. Pat. No. 7,528,291 (Herfert et al.) describes a color-stable superabsorbent polymer having long-term color stability, and methods of manufacturing the polymer, are disclosed. The color-stable superabsorbent polymer is prepared in the essential absence of a persulfate, and is subjected to a low dose of ultraviolet radiation. The resulting superabsorbent polymer resists color degradation during periods of extended storage, even at an elevated temperature and humidity.
U.S. Pat. No. 5,837,789 (Stockhousen) describes superabsorbing polymers for watery liquids, processes used in their production and their application. The polymers, based on monomers containing carboxylate groups and obtained by a special combination of cross-linking agents and other comonomers, show a combination of properties never attained before with regard to absorption rate, high retention at high absorption under pressure, low soluble content and good permeability of the gel layer for watery liquids under pressure load and stable surface cross-linkage.
U.S. Pat. No. 5,669,894 (Goldman et al.) describes absorbent polymers and materials useful in the containment of fluids, that have at least one region containing hydrogel-forming absorbent polymer in a concentration of from about 60 to 100% by weight and providing a gel-continuous fluid transportation zone when in a swollen state. This hydrogel-forming absorbent polymer has: (a) a Saline Flow Conductivity (SFC) value of at least about 30×10−7 cm·sup·3 sec/g; (b) a Performance under Pressure (PUP) capacity value of at least about 23 g/g under a confining pressure of 0.7 psi (5 kPa); and (c) a basis weight of at least about 10 gsm. In addition, the region where this hydrogel-forming absorbent polymer is present has, even when subjected to normal use conditions, sufficient wet integrity such that the gel-continuous zone substantially maintains its ability to acquire and transport fluids through the gel-continuous zone.
Published U.S. Patent Publication 20040077744 (Naylor) describes a process of preparing water soluble or water swellable polymer comprising the steps: a) forming an aqueous mixture comprising, i) a water soluble ethylenically unsaturated monomer or blend of monomers and, ii) at least one first ultra-violet initiator, iii) at least one second ultra-violet initiator; b) effecting polymerisation by subjecting the aqueous mixture formed in step (a) to irradiation by ultraviolet light at an intensity of up to 1,000 micrometers Wcm−2; subjecting the product of step (b) to irradiation by ultraviolet light of greater than 1,000 micrometers Wcm−2, characterised in that a significant amount of the first initiator(s) is/are activated in step (b) and a significant amount of the second initiator(s) is/are activated in step (c). The process is particularly suitable for making highly effective water soluble and water swellable polymers useful as flocculants, coagulants, rheology modifiers, dispersants, superabsorbents and binders etc.
U.S. Pat. No. 7,541,395 (Reimann) describes a process for producing an absorbent polymer including a first mixing event, in which a plurality of absorbent polymer particles (1) are mixed with a liquid (2) and a second mixing event, in which the liquid (2) is homogenized within the interior of the polymer particles. The polymer particles (1) in the first mixing event are mixed with a speed such that the kinetic energy of the individual polymer particles (1) is on average larger than the adhesion energy of the individual polymer particles (1), and the polymer particles (1) in the second mixing event are stirred at a lower speed than in the first mixing event. The different speeds effect a fluidization of the polymer particles (1), which prevents a clumping of the polymer particles (1) during the mixing event. The absorbent polymers thus produced are distinguished by a particularly rapid swelling behavior.